GeoPark Reports Third Quarter 2017 Results

Higher Production Doubles EBITDA, New Funding Raised and New Assets
Acquired

November 15, 2017 05:53 PM Eastern Time

BOGOTA, Colombia--(EON: Enhanced Online News)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE:GPRK), a leading
independent Latin American oil and gas explorer, operator and
consolidator with operations and growth platforms in Colombia, Chile,
Brazil, Argentina, and Peru reports its consolidated financial results
for the three-month period ended September 30, 2017 (“3Q2017”).

A conference call to discuss 3Q2017 Financial Results will be held on
November 16, 2017 at 10:00 am Eastern Standard Time.

All figures are expressed in US Dollars and growth comparisons refer to
the same period of the prior year, except when specified. Definitions
and terms used herein are provided in the Glossary at the end of this
document. This release does not contain all of the Company’s financial
information. As a result, this release should be read in conjunction
with GeoPark’s consolidated financial statements and the notes to those
statements for the period ended September 30, 2017, available on the
Company’s website.

THIRD QUARTER 2017 HIGHLIGHTS

Operational Results:

Oil and gas production up 28%

Consolidated oil and gas production up 28% to 28,325 boepd (up 8%
compared to 2Q2017)

Current total production of 30,000+ boepd (exceeds year-end exit
target)

Oil production increased by 37% to 23,237 bopd (up 6% compared to
2Q2017)

Colombian oil production increased by 43% to 22,301 bopd (up 6%
compared to 2Q2017). Total gross Colombian production is over 51,000
bopd – making GeoPark the third largest Colombian oil and gas operator

Successful drilling results in Colombia

In Llanos 34 block (GeoPark operated, 45% WI)

Tigana Norte 2 appraisal well was drilled to delineate the
northeastern boundary of the Tigana/Jacana complex and is currently
producing 2,700 bopd

Tigana Norte 3 appraisal well recently drilled outside the 3P outline
defined in the 2016 D&M reserves certification and approximately 50
feet down dip of the Tigana Norte 1 well and did not encounter the
oil-water contact. The well is currently producing 1,700 bopd

Tigana Norte 4 appraisal well currently being drilled further down dip
of Tigana Norte 3 well to continue delineating the northeastern
boundaries of the Tigana/Jacana complex

Jacana 10 appraisal well was drilled to test the northern limits of
the Jacana oil field and is currently producing 900 bopd

Jacana 12 appraisal well was drilled to test the southeastern boundary
of Jacana and is currently producing 2,800 bopd

Curucucu 1 exploration well was drilled exploring a new fault trend to
the east of Tigana/Jacana fault trend and is currently producing 1,100
bopd

James F. Park, Chief Executive Officer of GeoPark, said: “It was
another powerful quarter – with important operational, financial and
strategic wins – that continue building momentum for a successful
completion of 2017 and an exciting outlook for 2018. Our team did its
job by growing every component of our business plan. Production
continues to increase as our drilling keeps finding oil and pushing out
the boundaries of our key oil fields. Our cost reduction efforts and
innovations continue to decrease operating and capital costs. Our cash
flow more than doubled and key financial metrics showed improvement. We
added new highly-prospective acreage to our expanding project portfolio
by acquisitions in Colombia and Brazil and successfully closed a new
bond transaction providing more funds, longer maturities, more
flexibility and lower costs.”

CONSOLIDATED OPERATING PERFORMANCE

Key performance indicators:

Key Indicators

3Q2017

2Q2017

3Q2016

9M2017

9M2016

Oil productiona (bopd)

23,237

21,930

16,942

21,895

16,277

Gas production (mcfpd)

30,528

25,158

30,774

27,954

33,810

Average net production (boepd)

28,325

26,123

22,070

26,554

21,913

Brent oil price ($ per bbl)

52.1

51.0

46.9

52.6

43.1

Combined price ($ per boe)

33.0

32.2

26.3

32.6

23.6

⁻ Oil ($ per bbl)

34.6

33.4

26.9

34.1

23.3

⁻ Gas ($ per mcf)

5.3

5.5

4.5

5.3

4.5

Sale of crude oil ($ million)

68.4

64.1

38.4

187.0

95.9

Sale of gas ($ million)

13.6

11.1

11.5

36.9

36.5

Revenue ($ million)

81.9

75.2

49.9

223.8

132.3

Commodity Risk Management Contracts ($ million)

-8.3

5.9

-

3.0

-

Production & Operating Costsb ($ million)

-25.7

-25.3

-19.6

-68.5

-46.4

G&G, G&Ac and Selling Expenses ($ million)

-12.0

-13.9

-11.3

-36.1

-35.5

Adjusted EBITDA ($ million)

44.6

37.1

19.4

120.5

51.4

Adjusted EBITDA ($ per boe)

18.0

15.9

10.2

17.6

9.2

Operating Netback ($ per boe)

23.2

22.2

15.8

23.1

14.7

Profit (loss) ($ million)

-19.1

-1.1

-21.0

-14.4

-34.7

Capital Expenditures ($ million)

30.9

25.9

10.1

80.3

24.2

Cash and cash equivalents ($ million)

135.2

77.0

63.6

135.2

63.6

Short-term financial debt ($ million)

1.9

31.7

32.5

1.9

32.5

Long-term financial debt ($ million)

418.5

314.6

320.4

418.5

320.4

Net debt ($ million)

285.2

269.3

289.3

285.2

289.3

a)

Includes government royalties paid in-kind in Colombia for
approximately 774, 781 and 690 bopd in 3Q2017, 2Q2017 and 3Q2016
respectively. No royalties were paid in kind in Chile and Brazil.

b)

Production and Operating costs include operating costs and royalties
paid in cash.

c)

G&A expenses include $0.8, $0.8 and $0.9 million for 3Q2017, 2Q2017
and 3Q2016, respectively, of (non-cash) share-based payments that
are excluded from the adjusted EBITDA calculation.

Production: Consolidated oil and gas production grew by 28% to a
record 28,325 boepd in 3Q2017 compared to 22,070 boepd in 3Q2016. The
increase was mainly attributed to new production from the Tigana/Jacana
oil fields with four new wells put into production during the quarter.

Colombia: Average net oil and gas production increased by 43% to
22,367 boepd in 3Q2017 compared to 15,678 boepd in 3Q2016 due to
continued successful exploration and development drilling in the
Llanos 34 block.

Chile: Average net oil and gas production decreased by 25% to 2,817
boepd in 3Q2017 compared to 3,756 boepd in 3Q2016, due to natural
decline of the fields.

Brazil: Average net gas production increased by 19% to 3,141 boepd in
3Q2017 compared to 2,636 boepd in 3Q2016. Industrial demand for gas in
Brazil recovered in the third quarter.

The weight of crude oil in the production mix represented 82% in 3Q2017
(vs. 77% in 3Q2016) due to the successful drilling campaign in Llanos 34
block.

Tigana Norte 3 appraisal well successfully drilled outside the 3P
outline defined in the 2016 D&M reserves certification and
approximately 50 feet down dip of the Tigana Norte 1 well (previous
lowest known oil) and did not encounter the oil-water contact. The
well is currently producing 1,700 bopd.

Tigana Norte 4 appraisal well currently being drilled to continue
delineating the northeastern boundaries of the Tigana/Jacana complex.
The Tigana Norte 4 well is being drilled outside the 3P outline
defined in the 2016 D&M reserves certification and further down dip of
the recent Tigana Norte 3 well (now the lowest known oil). Currently
testing 3 wells, including Tigana Sur Oeste 7, Jacana 13 and 17.

Reference and Realized Oil Prices: Brent crude oil price averaged
$52.1 per bbl during 3Q2017, and the consolidated realized oil sales
price averaged $34.6 per bbl in 3Q2017, representing a 4% increase from
$33.4 per bbl in 2Q2017 and a 29% increase from $26.9 per bbl in 3Q2016.
Differences between reference and realized prices are a result of
commercial and transportation discounts as well as the Vasconia price
differential in Colombia, which narrowed to $2.8 per bbl in 3Q2017 from
$5.7 per bbl in 3Q2016.

The following table provides a breakdown of reference and net realized
oil prices in Colombia and Chile in 3Q2017:

3Q2017 - Realized Oil Prices

($ per bbl)

Colombia

Chile

Brent oil price

52.1

52.1

Vasconia differential

(2.8)

-

Commercial and transportation discounts

(15.2)

(7.8)

Realized oil price

34.1

44.3

Weight on Oil Sales Mix

96%

4%

Commodity Risk Management Contracts - Brent Oil Price: In 3Q2017
the Company recorded the following amounts related to commodity hedges
to mitigate the risk exposure to changes in the Brent oil price.
Realized gains reflect cash settled transactions and unrealized
gains/losses reflect non-cash changes between the contract values and
the forward Brent oil curve.

3Q2017 – Commodity Risk Management Contracts

($ million)

Realized cash gain

1.5

Non-cash unrealized losses

-9.8

Net effect

-8.3

The Company has the following commodity risk management contracts
(reference ICE Brent), in place as of the date of this release:

Period Hedged

Type

Volume bopd

Contract details ($ per bbl)

Purchased Put

Sold Put

Sold Call

4Q2017

Zero premium collar

12,000

50.0-51.0

-

54.9-57.5

1Q2018

Zero premium collarZero premium 3 way

9,0002,0002,000

50.0-52.042.043.0

-52.053.0

54.9-60.059.5-59.659.5-59.6

Total: 13,000

2Q2018

Zero premium collarZero premium 3 wayZero premium 3 way

4,0004,0002,000

52.042.043.0

-52.053.0

58.3-60.058.4-64.658.4-64.6

Total: 10,000

For further details, please refer to Note 4 of GeoPark’s consolidated
financial statements for the period ended September 30, 2017, available
on the Company’s website.

Revenue: Consolidated revenues increased by 64% to $81.9 million
in 3Q2017, compared to $49.9 million in 3Q2016, mainly driven by higher
oil and gas revenues.

Sales of crude oil: Consolidated oil
revenues increased by 78% to $68.4 million in 3Q2017, driven by a 39%
increase in oil sales volumes and a 28% increase in realized oil prices.
Oil revenues represented 83% of total revenues compared to 77% in 3Q2016.

Colombia: In 3Q2017, oil revenues increased by 90% to $64.3 million
mainly due to increased sales volumes and higher realized prices. Oil
sales volumes increased by 45% to 21,378 bopd. Realized oil prices
increased by 31% to $34.1 per bbl, in line with higher Brent prices
and a lower Vasconia discount. Colombia earn-out payments (deducted
from Colombia oil revenues) increased to $2.8 million in 3Q2017,
compared to $1.3 million in 3Q2016, in line with increased production
and higher oil revenues.

Chile: In 3Q2017, oil revenues decreased by 14% to $3.8 million due to
lower sales volumes partially offset by higher realized prices. Oil
sales volumes decreased by 26% to 928 bopd and realized oil prices
increased by 17% to $44.3 per barrel, in line with higher Brent prices.

Sales of gas: Consolidated gas revenues
increased by 18% to $13.6 million in 3Q2017 compared to $11.5 million in
3Q2016 due to 17% higher realized gas prices and 1% higher gas sales
volumes.

Brazil: In 3Q2017, gas revenues increased by 33% to $9.2 million, due
to both higher realized prices and sales volumes. Gas prices, net of
taxes, increased by 12% to $5.9 per mcf ($35.2 per boe) due to the
annual gas price inflation adjustment of approximately 7%, effective
January 2017, and a slight 3% appreciation of the local currency. Gas
sales volumes increased by 18% to 17,056 mcfpd (2,842 boepd),
primarily due to higher gas consumption by Brazilian industrial users.

Production and operating costs[1]:
Consolidated production and operating costs increased by 31% to $25.7
million in 3Q2017, compared to $19.6 million in 3Q2016, mainly due to
high price royalties that increased the total by $4.1 million, and to a
lesser extent, higher operating costs of $2.0 million, due to a 39%
increase in oil sales volumes. The Jacana oil field in Llanos 34 block
in Colombia accumulated more than five million barrels of production
which triggered Colombia’s “high price” royalty scheme beginning in
mid-2Q2017. Thus, cash royalties as a percentage of revenues were 9%
compared to 7% in 3Q2016.

Adjusting for increased production, consolidated operating costs per
barrel actually decreased to $7.3 per boe in 3Q2017 from $8.5 per boe a
year earlier. Apart from lower road maintenance and well-intervention
costs, the improvement reflects the company´s continuous efforts to
reduce operating costs.

By country, production and operating costs were as follows:

Colombia: Operating costs increased by 11% to $10.8 million in 3Q2017
from $9.8 million in 3Q2016, mainly resulting from a 45% increase in
sales volumes. Compared to 3Q2016, there were lower road maintenance
works, pulling and other well intervention activities. Operating costs
per boe decreased to $5.5 per boe in 3Q2017 from $7.1 per boe in
3Q2016.

Chile: Operating costs increased by 4% to $5.3 million in 3Q2017 from
$5.0 million in 3Q2016 mainly due to higher pulling, well intervention
activities and consumables, and to a lesser extent to the appreciation
of the Chilean peso (+3%). Operating costs per boe increased by 36% to
$21.5 per boe due to the impact of lower absorption of fixed costs
from lower sales volumes.

Brazil: Operating costs increased to $2.2 million in 3Q2017 from $1.5
million in 3Q2016, mainly due to increased volumes (+18%) and higher
maintenance costs in Manati ($0.7 million higher in 3Q2017 vs 3Q2016)
and, to a lesser extent, the appreciation of the Brazilian real (+3%).
Operating costs per boe increased to $8.2 per boe from $6.6 in 3Q2016.

Royalties: Consolidated royalties paid in cash (reported in Production
and Operating Costs) increased by $4.1 million to $7.4 million in
3Q2017, compared to $3.3 million in 3Q2016, mainly resulting from
increased production, higher oil prices and the “high price” royalty for
the Jacana oil field in Llanos 34 block beginning in 3Q2017. Thus,
consolidated royalties increased to 9% of revenue versus 7% in 3Q2016.

Selling expenses: Consolidated selling expenses decreased to $0.3
million in 3Q2017 compared to $0.5 million in 3Q2016.

Administrative, Geological and Geophysical expenses: Consolidated
G&A and G&G expenses increased by 7% to $11.6 million in 3Q2017 compared
to $10.8 million in 3Q2016. Consolidated G&A and G&G costs per boe
decreased by 7% to $5.2 per boe in 3Q2017 (vs. $5.6 per boe in 3Q2016).

Adjusted EBITDA: Consolidated adjusted EBITDA1
strongly grew by 131% to $44.6 million or $18.0 per boe in 3Q2017
compared to $19.4 million or $10.2 per boe in 3Q2016, mainly driven by
the combination of increased production levels and higher realized oil
and gas prices.

Colombia: Adjusted EBITDA of $41.6 million in 3Q2017

Chile: Adjusted EBITDA of $0.8 million in 3Q2017

Brazil: Adjusted EBITDA of $5.4 million in 3Q2017

Corporate, Argentina and Peru: Adjusted EBITDA of negative $3.2
million in 3Q2017

_______________

[1]

Production and Operating Costs = Operating Costs plus Royalties

1

See “Reconciliation of adjusted EBITDA to Profit (Loss) before
income tax and adjusted EBITDA per boe” included in this press
release.

The table below shows production, volumes sold and breakdown of the most
significant components of adjusted EBITDA for 3Q2017 and 3Q2016, on a
per country and per barrel basis:

Adjusted EBITDA/boe

Colombia

Chile

Brazil

Total

3Q17

3Q16

3Q17

3Q16

3Q17

3Q16

3Q17

3Q16

Production (boepd)

22,367

15,678

2,817

3,756

3,141

2,636

28,325

22,070

Stock variation /RIKa

(935)

(944)

(158)

(301)

(254)

(199)

(1,347)

(1,444)

Sales volume (boepd)

21,432

14,734

2,659

3,455

2,887

2,437

26,978

20,626

% Oil

100%

100%

35%

36%

2%

2%

83%

78%

($ per boe)

Realized oil price

34.1

25.9

44.3

37.8

59.4

48.3

34.6

26.9

Realized gas priceb

-

-

26.1

20.8

35.2

31.5

31.8

27.1

Earn-out

(1.3)

(0.9)

-

-

-

-

(0.9)

(0.6)

Combined Price

32.7

25.0

32.4

27.0

35.6

31.7

33.0

26.3

Commodity Risk Management Contracts

0.8

-

-

-

-

-

0.6

-

Operating costs

(5.5)

(7.1)

(21.5)

(15.9)

(8.2)

(6.6)

(7.3)

(8.5)

Royalties in cash

(3.1)

(1.7)

(1.3)

(1.1)

(3.4)

(3.1)

(3.0)

(1.7)

Selling & other expenses

0.0

(0.1)

(0.6)

(0.7)

-

-

(0.1)

(0.3)

Operating Netback/boe

24.9

16.3

9.0

9.4

24.0

22.1

23.2

15.8

G&A, G&G

(5.2)

(5.6)

Adjusted EBITDA/boe

18.0

10.2

a)

RIK (Royalties in Kind). Includes royalties paid in kind in Colombia
for approximately 774 and 690 bopd in 3Q2017 and 3Q2016,
respectively. No royalties were paid in kind in Chile and Brazil.

b)

Conversion rate of mcf/boe=1/6

Depreciation: Consolidated depreciation decreased by 6% to $19.4
million in 3Q2017, compared to $20.8 million in 3Q2016, due to lower
depreciation costs per boe as a consequence of drilling successes and
increased reserves, partially offset by higher volumes sold.
Depreciation costs per boe declined by 28% to $7.8 per boe.

Write-off of unsuccessful exploration efforts: Consolidated
write-off of unsuccessful exploration efforts amounted to $0.2 million
in 3Q2017, compared to $13.3 million in 3Q2016. Amounts recorded in
3Q2016 correspond to non-cash charges from seismic and exploration
activities associated to the relinquishment of blocks with no production
and no reserves in Colombia and Brazil, plus unsuccessful exploratory
efforts in Chile.

Other expenses: Other operating expenses amounted to $0.4 million
in 3Q2017, compared to $1.0 million gain in 3Q2016.

CONSOLIDATED NON-OPERATING RESULTS AND PROFIT FOR THE PERIOD

Net financial expenses: Net financial costs increased to $26.6
million in 3Q2017, compared to $8.6 million in 3Q2016. Amounts recorded
in 3Q2017 include $17.6 million related to one-time costs on the
cancellation of 2020 Notes (see “Financial Ratios” section below for
further details). Excluding these costs, net financial expenses amounted
to $9.0 million in 3Q2017.

Foreign exchange: Net foreign exchange charges amounted to a $3.2
million gain in 3Q2017 compared to a $1.8 million loss in 3Q2016, mainly
due to the appreciation of the Brazilian real in 3Q2017 versus the
depreciation in 3Q2016. Foreign exchange differences resulted from
differences in the US Dollar-denominated debt incurred at the local
subsidiary level and the underlying functional currency, the Brazilian
real.

Income tax: Income taxes amounted to an $11.6 million loss in
3Q2017, as compared to a $3.5 million gain in 3Q2016, in line with
operating profits recorded in 3Q2017 versus operating losses recorded in
3Q2016.

Net income: Net losses amounted to $19.1 million in 3Q2017
compared to $21.0 million in 3Q2016. The net loss in 3Q2017 mainly
relates to one-time costs from the cancellation of 2020 Notes.

BALANCE SHEET

Cash and cash equivalents: Cash and cash equivalents totaled
$135.2 million as of September 30, 2017. Year-end 2016 cash and cash
equivalents amounted to $73.6 million. The difference reflects cash
generated from operating activities of $117.4 million and cash from
financing activities of $26.4 million, partially offset by cash used in
investing activities of $80.3 million.

Cash from financing activities of $26.4 million includes net proceeds
from the issuance of 2024 Notes of $420.8 million, offset by: (i)
principal paid of $353.9 million related to the payment of 2020 Notes
and the prepayment of the Itau loan, (ii) cancellation costs of $17.6,
and (iii) interest payments of $22.4 million.

Prepayment facility and credit lines available: As of September
30, 2017, the Company had in place an offtake and prepayment agreement
with Trafigura of up to $100 million ($12.5 million outstanding as of
September 30, 2017) and approximately $28 million in uncommitted credit
lines.

Financial debt: Total financial debt (net of issuance costs)
amounted to $420.4 million, including the $425 million 2024 Notes issued
in September 2017. Short-term debt amounted to $1.9 million as of
September 30, 2017.

FINANCIAL RATIOSa

($ million)

At period-end

FinancialDebt

Cash and CashEquivalents

Net Debt

Net Debt/ LTMAdj. EBITDA

LTM InterestCoverage

3Q2016

352.9

63.6

289.3

4.7x

2.0x

4Q2016

358.7

73.6

285.1

3.6x

2.7x

1Q2017

341.7

70.3

271.4

2.6x

3.4x

2Q2017

346.3

77.0

269.3

2.2x

4.1x

3Q2017

420.4

135.2

285.2

1.9x

5.3x

a)

Based on trailing 12-month financial results.

Issuance of 2024 Notes: During September 2017, the Company
successfully placed $425 million notes (“2024 Notes”) in accordance with
Rule 144A under the United States Securities Act, and outside the United
States to non-U.S. persons in accordance with Regulation S under the
United States Securities Act. The 2024 Notes carry a coupon of 6.50% per
annum. Funds were used to repay financial debt, to provide financial
flexibility and for general corporate purposes.

The indenture governing the 2024 Notes includes incurrence test
covenants that provides among other things, that, during the first two
years from the issuance date, the net Debt to adjusted EBITDA ratio
should not exceed 3.5 times and the adjusted EBITDA to interest ratio
should exceed 2 times. Failure to comply with the incurrence test
covenants would not trigger an event of default. As of the date of this
release the Company is in compliance with all provisions and covenants.

IN MEMORIAM

GeoPark deeply laments the passing of Michael Dingman on October 3,
2017, a special friend, valued colleague, and a giant in international
industry and finance, who served on GeoPark's Board of Directors and
passionately supported and advised GeoPark’s management team. Michael´s
extensive Board knowledge and experience on the boards of major listed
companies greatly benefited the GeoPark Board of Directors.

SELECTED INFORMATION BY BUSINESS SEGMENT

(UNAUDITED)

Colombia

3Q2017

3Q2016

Revenue ($ million)

64.5

34.2

Production and Operating Costsa ($ million)

-17.0

-12.0

Adjusted EBITDA ($ million)

41.6

17.4

Capital Expendituresb ($ million)

22.5

8.2

Chile

3Q2017

3Q2016

Sale of crude oil ($ million)

3.8

4.4

Sale of gas ($ million)

4.2

4.2

Revenue ($ million)

7.9

8.6

Production and Operating Costsa ($ million)

-5.6

-5.4

Adjusted EBITDA ($ million)

0.8

1.0

Capital Expendituresb ($ million)

4.6

0.0

Brazil

3Q2017

3Q2016

Sale of crude oil ($ million)

0.2

0.2

Sale of gas ($ million)

9.2

6.9

Revenue ($ million)

9.4

7.1

Production and Operating Costsa ($ million)

-3.1

-2.2

Adjusted EBITDA ($ million)

5.4

4.4

Capital Expendituresb ($ million)

0.0

0.6

a)

Production and Operating = Operating Costs + Royalties.

b)

The difference with the reported figure in Key Indicators table
corresponds mainly to capital expenditures in Argentina and to a
lesser extent in Peru.

CONSOLIDATED STATEMENT OF INCOME

(UNAUDITED)

(In millions of $)

3Q2017

3Q2016

9M2017

9M2016

REVENUE

Sale of crude oil

68.4

38.4

187.0

95.9

Sale of gas

13.6

11.5

36.9

36.5

TOTAL REVENUE

81.9

49.9

223.8

132.3

Commodity risk management contracts

-8.3

-

3.0

-

Production and operating costs

-25.7

-19.6

-68.5

-46.4

Geological and geophysical expenses (G&G)

-0.7

-2.3

-3.8

-7.6

Administrative expenses (G&A)

-10.9

-8.5

-31.4

-24.2

Selling expenses

-0.3

-0.5

-0.9

-3.6

Depreciation

-19.4

-20.8

-55.1

-58.9

Write-off of unsuccessful exploration efforts

-0.2

-13.3

-4.8

-13.7

Impairment for non-financial assets

-

-

-

-

Other operating

-0.4

1.0

-2.4

-0.4

OPERATING PROFIT (LOSS)

15.9

-14.1

59.9

-22.6

Financial costs, net

-26.6

-8.6

-43.3

-25.2

Foreign exchange gain (loss)

3.2

-1.8

1.4

15.3

PROFIT (LOSS) BEFORE INCOME TAX

-7.5

-24.5

18.0

-32.5

Income tax

-11.6

3.5

-32.4

-2.1

PROFIT (LOSS) FOR THE PERIOD

-19.1

-21.0

-14.4

-34.7

Non-controlling interest

0.8

-2.9

5.4

-6.0

ATTRIBUTABLE TO OWNERS OF GEOPARK

-19.9

-18.1

-19.8

-28.7

SUMMARIZED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(In millions of $)

Sep '17

Dec '16

(Unaudited)

(Audited)

Non-Current Assets

Property, plant and equipment

497.9

473.6

Other non-current assets

46.9

45.7

Total Non-Current Assets

544.8

519.3

Current Assets

Inventories

4.7

3.5

Trade receivables

14.4

18.4

Other current assets

34.0

25.7

Cash at bank and in hand

135.2

73.6

Total Current Assets

188.3

121.2

Total Assets

733.1

640.5

Equity

Equity attributable to owners of GeoPark

90.0

105.8

Non-controlling interest

40.9

35.8

Total Equity

130.9

141.6

Non-Current Liabilities

Borrowings

418.5

319.4

Other non-current liabilities

78.8

80.0

Total Non-Current Liabilities

497.3

399.4

Current Liabilities

Borrowings

1.9

39.3

Other current liabilities

103.0

60.2

Total Current Liabilities

104.9

99.5

Total Liabilities

602.2

498.9

Total Liabilities and Equity

733.1

640.5

SUMMARIZED CONSOLIDATED STATEMENT OF CASH FLOWS

(UNAUDITED)

(In millions of $)

3Q2017

3Q2016

9M2017

9M2016

Cash flows from operating activities

38.2

26.4

117.4

54.9

Cash flows used in investing activities

-30.9

-10.1

-80.3

-24.2

Cash flows from (used) in financing activities

51.4

-31.3

26.4

-49.4

RECONCILIATION OF ADJUSTED EBITDA TO PROFIT (LOSS) BEFORE INCOME
TAX

(UNAUDITED)

9M2017 (In millions of $)

Colombia

Chile

Brazil

Other

Total

Adjusted EBITDA

116.7

2.9

13.0

-12.0

120.5

Depreciation

-29.2

-18.0

-7.7

-0.2

-55.1

Commodity Risk Management Contracts

-0.7

-

-

-

-0.7

Write-offs unsuccessful exploration efforts

-1.6

-

-3.0

-0.2

-4.8

Share Based Payments

-0.4

-0.3

-0.1

-2.3

-3.1

Others

4.1

0.6

-0.5

-1.1

3.1

OPERATING PROFIT (LOSS)

88.8

-14.7

1.7

-15.9

59.9

Financial costs, net

-43.3

Foreign Exchange charges, net

1.4

PROFIT (LOSS) BEFORE INCOME TAX

18.0

9M2016 (In millions of $)

Colombia

Chile

Brazil

Other

Total

Adjusted EBITDA

40.5

4.5

14.1

-7.7

51.4

Depreciation

-24.5

-24.1

-10.1

-0.2

-58.9

Commodity Risk Management Contracts

-

-

-

-

-

Write-offs unsuccessful exploration efforts

-7.4

-1.7

-4.6

-

-13.7

Share Based Payments

-0.5

-0.3

0.0

-1.1

-1.9

Others

0.3

0.9

1.0

-1.6

0.6

OPERATING PROFIT (LOSS)

8.3

-20.6

0.4

-10.7

-22.6

Financial costs, net

-25.2

Foreign Exchange charges, net

15.3

PROFIT (LOSS) BEFORE INCOME TAX

-32.5

RECONCILIATION OF LAST TWELVE MONTHS ADJUSTED EBITDA TO PROFIT
(LOSS) BEFORE INCOME TAX

Adjusted EBITDA is defined as profit for the period before net
finance costs, income tax, depreciation, amortization, certain
non-cash items such as impairments and write-offs of unsuccessful
exploration efforts, accrual of share-based payments, unrealized
results on commodity risk management contracts and other
non-recurring events

Revenue, less production and operating costs (net of depreciation
charges and accrual of stock options and stock awards) and selling
expenses, divided by total boe sales volumes. Operating netback is
equivalent to adjusted EBITDA net of cash expenses included in
Administrative, Geological and Geophysical and Other operating costs

PRMS

Petroleum Resources Management System

SPE

Society of Petroleum Engineers

SQ KM

Square kilometers

WI

Working interest

NOTICE

Additional information about GeoPark can be found in the “Investor
Support” section on the website at www.geo-park.com.

Rounding amounts and percentages: Certain amounts and percentages
included in this press release have been rounded for ease of
presentation. Percentage figures included in this press release have not
in all cases been calculated on the basis of such rounded figures, but
on the basis of such amounts prior to rounding. For this reason, certain
percentage amounts in this press release may vary from those obtained by
performing the same calculations using the figures in the financial
statements. In addition, certain other amounts that appear in this press
release may not sum due to rounding.

This press release contains certain oil and gas metrics, including
information per share, operating netback, reserve life index, and
others, which do not have standardized meanings or standard methods of
calculation and therefore such measures may not be comparable to similar
measures used by other companies. Such metrics have been included herein
to provide readers with additional measures to evaluate the Company's
performance; however, such measures are not reliable indicators of the
future performance of the Company and future performance may not compare
to the performance in previous periods.

CAUTIONARY STATEMENTS RELEVANT TO FORWARD-LOOKING INFORMATION

This press release contains statements that constitute forward-looking
statements. Many of the forward-looking statements contained in this
press release can be identified by the use of forward-looking words such
as ‘‘anticipate,’’ ‘‘believe,’’ ‘‘could,’’ ‘‘expect,’’ ‘‘should,’’
‘‘plan,’’ ‘‘intend,’’ ‘‘will,’’ ‘‘estimate’’ and ‘‘potential,’’ among
others.

Forward-looking statements that appear in a number of places in this
press release include, but are not limited to, statements regarding the
intent, belief or current expectations, regarding various matters,
including expected 2017 production growth and performance, operating
netback per boe and capital expenditures plan. Forward-looking
statements are based on management’s beliefs and assumptions, and on
information currently available to the management. Such statements are
subject to risks and uncertainties, and actual results may differ
materially from those expressed or implied in the forward-looking
statements due to various factors.

Forward-looking statements speak only as of the date they are made, and
the Company does not undertake any obligation to update them in light of
new information or future developments or to release publicly any
revisions to these statements in order to reflect later events or
circumstances, or to reflect the occurrence of unanticipated events. For
a discussion of the risks facing the Company which could affect whether
these forward-looking statements are realized, see filings with the U.S.
Securities and Exchange Commission.

Oil and gas production figures included in this release are stated
before the effect of royalties paid in kind, consumption and losses.
Annual production per day is obtained by dividing total production for
365 days.

Information about oil and gas reserves: The SEC permits oil and
gas companies, in their filings with the SEC, to disclose only proven,
probable and possible reserves that meet the SEC's definitions for such
terms. GeoPark uses certain terms in this press release, such as "PRMS
Reserves" that the SEC's guidelines do not permit GeoPark from including
in filings with the SEC. As a result, the information in the Company’s
SEC filings with respect to reserves will differ significantly from the
information in this press release.

NPV10 for PRMS 1P, 2P and 3P reserves is not a substitute for the
standardized measure of discounted future net cash flows for SEC proved
reserves.

The reserve estimates provided in this release are estimates only, and
there is no guarantee that the estimated reserves will be recovered.
Actual reserves may eventually prove to be greater than, or less than,
the estimates provided herein. Statements relating to reserves are by
their nature forward-looking statements.

Adjusted EBITDA: The Company defines adjusted EBITDA as profit
for the period before net finance costs, income tax, depreciation,
amortization and certain non-cash items such as impairments and
write-offs of unsuccessful exploration and evaluation assets, accrual of
stock options stock awards, unrealized results on commodity risk
management contracts and other non-recurring events. Adjusted EBITDA is
not a measure of profit or cash flows as determined by IFRS. The Company
believes adjusted EBITDA is useful because it allows us to more
effectively evaluate our operating performance and compare the results
of our operations from period to period without regard to our financing
methods or capital structure. The Company excludes the items listed
above from profit for the period in arriving at adjusted EBITDA because
these amounts can vary substantially from company to company within our
industry depending upon accounting methods and book values of assets,
capital structures and the method by which the assets were acquired.
Adjusted EBITDA should not be considered as an alternative to, or more
meaningful than, profit for the period or cash flows from operating
activities as determined in accordance with IFRS or as an indicator of
our operating performance or liquidity. Certain items excluded from
adjusted EBITDA are significant components in understanding and
assessing a company’s financial performance, such as a company’s cost of
capital and tax structure and significant and/or recurring write-offs,
as well as the historic costs of depreciable assets, none of which are
components of adjusted EBITDA. The Company’s computation of adjusted
EBITDA may not be comparable to other similarly titled measures of other
companies. For a reconciliation of adjusted EBITDA to the IFRS financial
measure of profit for the year or corresponding period, see the
accompanying financial tables.

Operating netback per boe should not be considered as an alternative to,
or more meaningful than, profit for the period or cash flows from
operating activities as determined in accordance with IFRS or as an
indicator of our operating performance or liquidity. Certain items
excluded from Operating Netback per boe are significant components in
understanding and assessing a company’s financial performance, such as a
company’s cost of capital and tax structure and significant and/or
recurring write-offs, as well as the historic costs of depreciable
assets, none of which are components of Operating Netback per boe. The
Company’s computation of Operating Netback per boe may not be comparable
to other similarly titled measures of other companies. For a
reconciliation of Operating Netback per boe to the IFRS financial
measure of profit for the year or corresponding period, see the
accompanying financial tables.

BOGOTA--(EON: Enhanced Online News)--GeoPark Limited (“GeoPark” or the “Company”) (NYSE: “GPRK”), a leading independent Latin American oil and gas explorer, operator and consolidator with operation... more »